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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus and may not contain all of the information that you should consider before investing in the shares. You are urged to read this prospectus in its entirety, including the information under “Risk Factors” and our financial statements and related notes included elsewhere in this Prospectus.

Our Company

Overview

HNR Acquisition Corp, was incorporated in Delaware as a blank check company formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses or entities. Prior to executing the MIPA (as defined below), our efforts were limited to organizational activities, completion of an initial public offering and the evaluation of possible business combinations. We closed our initial public offering on February 15, 2022. We have identified Pogo (as defined below) as the initial target for our initial business combination. Our efforts to identify a prospective target business were limited to a particular industry or geographic region. While we may pursue an acquisition opportunity in any industry or sector, we focused on assets used in exploring, developing, producing, transporting, storing, gathering, processing, fractionating, refining, distributing or marketing of natural gas, natural gas liquids, crude oil or refined products in North America.

We primarily intended to identify and acquire a business that could benefit from a hands-on owner with extensive operational experience in the energy sector in North America and that presents potential for an attractive risk-adjusted return profile under our stewardship. The largest oil and gas companies, including ExxonMobil, Royal Dutch Shell, Chevron and BP, are projected to sell a combined $100 billion in oil and gas assets around the world as they focus on top-performing regions according to a new analysis from consulting firm Rystad (October 2020). Our management team has extensive experience in identifying and executing such potential acquisitions across the upstream and midstream energy sectors. In addition, our team has significant hands-on experience working with private companies in preparing for and executing an initial public offering and serving as active owners and directors by working closely with these companies to continue their transformations and to create value in the public markets.

We believe that our management team is well positioned to identify attractive risk-adjusted returns in the marketplace and that their contacts and transaction sources, ranging from industry executives, private owners, private equity funds, and investment bankers, will enable us to pursue a broad range of opportunities.

We will seek to capitalize on the extensive experience of each of the members of our management team who have more than 40 years average experience in the energy industry. Mr. Donald H. Goree, our Chairman and Chief Executive Officer has over 40 years’ experience in the oil and gas industry involving exploration and production, oil and gas pipeline construction and operations, natural gas gathering, processing and gas liquification. Mr. Goree was the Founder and President of Goree Petroleum Inc., a corporation engaged in oil and gas exploration and production in premiere basins throughout the United States for 35 years. Currently, Mr. Goree is the Founder, Chairman and Chief Executive officer of Houston Natural Resources, Inc., a global natural resource corporation located in Houston, Texas and the controlling member of our sponsor. Mr. Goree also previously served as Founder, Chairman and Chief Executive officer of Global Xchange Solutions AG., a publicly-reporting, private equity, investment bank and market-making firm, based in Zurich, Switzerland, with offices in Frankfurt, Germany and London, United Kingdom. Global Xchange Solutions sponsored listings of private companies to the London Stock Exchange, AIM, the Frankfurt Stock Exchange, the Berlin Stock Exchange and the Börse Stuttgart, and provided public company development and market development advice. Mr. Goree also previously served as Chairman and Chief Executive officer of Azur Holdings, Inc., a Fort Lauderdale, Florida-based, OTC-listed luxury real estate developer of mid-rise waterfront condominiums. Mr. Donald W. Orr, our President, is a degreed geologist with over 42 years of experience in petroleum geology and production operations. Mr. Orr began his career as a junior geologist with Texas Oil and Gas Corporation in 1976, and was elevated within two years to a supervisory role overseeing over five geologists on his team, most of whom had more experience than Mr. Orr. In February 1979, Mr. Orr helped form American Shoreline, Inc., an independent oil and gas company. Mr. Orr formerly held a position with Seven Energy LLC, a wholly owned subsidiary of Weatherford International plc in 2005, where he helped pioneered numerous innovations in underbalanced drilling, or UBD, including drilling with unconventional materials and devising the methodology for unlocking the productive capacity of the Buda Lime through the use of UBD. In June 2009, Mr. Orr founded XNP Resources, LLC, an independent oil and gas company engaged in the exploration, development, production, and acquisition of oil and natural gas resources. Shortly thereafter, XNP Resources teamed up with Tahoe Energy Partners, LLC in 2012 to acquire oil and gas leases for drilling in the Rocky Mountain region. At Mr. Orr’s direction, XNP Resources began acquiring a strategic leasehold position in the Sand Wash Basin in Colorado. XNP Resources was able to secure a major leasehold position in the heart of what has become the highly competitive Niobrara Shale formation in western Colorado. Since 2014, Mr. Orr has been developing an unconventional resource play in Alaska that contains over 600 billion cubic feet of gas in stacked coal reservoirs. More recently, Mr. Orr assembled a team of oil and gas professionals in order to study certain oil provinces in Columbia. S.A.

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The past performance of the members of our management team is not a guarantee that we will be able to identify a suitable candidate for our initial business combination or of success with respect to any business combination we may consummate. You should not rely on the historical record of the performance of our management team as indicative of our future performance. Additionally, in the course of their respective careers, members of our management team have been involved in businesses and deals that were unsuccessful. None of our officers and directors has experience with special purpose acquisition companies, or SPACs.

We intend to effectuate a business combination using cash from the proceeds of our Initial Public Offering and the sale of our capital stock, debt or a combination of cash, stock and debt.

The issuance of additional shares of our stock in a business combination:

Similarly, if we issue debt securities, it could result in:

As indicated in the accompanying financial statements, at June 30, 2023, we had $813,177 in cash and a working capital deficit of $1,699,274, which excludes franchise and income taxes payable as the net amounts can be paid from the interest earned in the Trust Account. We expect to continue to incur significant costs in the pursuit of our acquisition plans. We cannot assure you that our plans to complete our initial business combination will be successful.

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Purchase

On December 27, 2022, we, entered into a Membership Interest Purchase Agreement (the “Original MIPA”) with CIC Pogo LP, a Delaware limited partnership (“CIC”), DenCo Resources, LLC, a Texas limited liability company (“DenCo”), Pogo Resources Management, LLC, a Texas limited liability company (“Pogo Management”), 4400 Holdings, LLC, a Texas limited liability company (“4400” and, together with CIC, DenCo and Pogo Management, collectively, “Seller” and each a “Seller”), and, solely with respect to Section 7.20 of the Original MIPA, HNRAC Sponsors LLC, a Delaware limited liability company (“Sponsor”). On August 28, 2023, we, HNRA Upstream, LLC, a newly formed Delaware limited liability company which is managed by us, and is a subsidiary of ours (“OpCo”), and HNRA Partner, Inc., a newly formed Delaware corporation and wholly owned subsidiary of ours (“SPAC Subsidiary”, and together with the us and OpCo, “Buyer” and each a “Buyer”), entered into an Amended and Restated Membership Interest Purchase Agreement (the “A&R MIPA”) with Seller, and, solely with respect to Section 6.20 of the A&R MIPA, the Sponsor, which amended and restated the Original MIPA in its entirety (as amended and restated, the “MIPA”). Post-purchase, we will be organized in an “Up-C” structure.

Pursuant to the MIPA, and subject to the terms, provisions, and conditions set forth therein, at the closing of the transactions contemplated by the MIPA (the “Closing”), (i) (A) we will contribute to OpCo (1) all of its assets (excluding its interests in OpCo and the aggregate amount of cash required to satisfy any exercise by stockholders of their redemption rights) and (2) 2,000,000 newly issued shares of our Class B Common Stock, par value $0.0001 per share (such shares, the “Seller Class B Shares”) for purposes of delivery to Seller, and (B) in exchange therefor, OpCo will issue to us a number of Class A common units (the “OpCo Class A Units”) of OpCo equal to the number of total shares of our Class A Common Stock, par value $0.0001 per share, issued and outstanding immediately after the Closing (taking into account and following the exercise of redemption rights) (such transactions, the “SPAC Contribution”), (ii) immediately following the SPAC Contribution, OpCo will contribute $900,000 to SPAC Subsidiary in exchange for 100% of the outstanding common stock of SPAC Subsidiary (the “SPAC Subsidiary Contribution”), and (iii) immediately following the SPAC Subsidiary Seller shall sell, contribute, assign, and convey to (A) OpCo, and OpCo shall acquire and accept from Seller, ninety-nine percent (99.0%) of the outstanding membership interests of Pogo Resources, LLC, a Texas limited liability company (“Pogo” or the “Target”), and (B) SPAC Subsidiary, and SPAC Subsidiary shall purchase and accept from Seller, one percent (1.0%) of the outstanding membership interest of Target (together with the ninety-nine (99.0%) interest, the “Target Interests”), in each case, in exchange for (x) $900,000 of the Cash Consideration (as defined below) in the case of SPAC Subsidiary and (y) the remainder of the Aggregate Consideration (as defined below) in the case of OpCo.

The “Aggregate Consideration” for the Target Interests will be (a), cash in the amount of $63,000,000 in immediately available funds (the “Cash Consideration”), (b) 2,000,000 Class B common units of OpCo (“OpCo Class B Units”) valued at $10.00 per unit (the “Common Unit Consideration”), which will be equal to and exchangeable into 2,000,000 shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right (as defined below), as reflected in the amended and restated limited liability company agreement of OpCo that will be effective at Closing (the “A&R OpCo LLC Agreement”) and (c) and the Seller Class B Shares; provided, that (i) a portion of the Cash Consideration not to exceed $15,000,000 may be payable through a promissory note to Seller (the “Seller Promissory Note”) to the extent the amount available for payment of the Cash Consideration at Closing (the “Minimum Cash Amount”) is less than $63,000,000 and (ii) a portion of the Cash Consideration not to exceed $20,000,000 may be payable through the issuance of up to 2,000,000 preferred units (the “OpCo Preferred Units” and together with the Opco Class A Units and the OpCo Class B Units, the “OpCo Units”) of OpCo (the “Preferred Unit Consideration”, and, together with the Common Unit Consideration, the “Unit Consideration”), to the extent the Minimum Cash Amount is less than $48,000,000. At Closing, 500,000 OpCo Class B Units (the “Escrowed Unit Consideration”) shall be placed in escrow with an escrow for the benefit of Buyer pursuant to an escrow agreement and the indemnity provisions of the MIPA. The Aggregate Consideration is subject to adjustment in accordance with the MIPA.

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Immediately following the Closing, we will be the sole manager of and control OpCo, and will own 100% of the outstanding OpCo Class A Units. Further, Seller will own 100% of the outstanding OpCo Class B Units, shares of Class B Common Stock, and OpCo Preferred Units.

Our current shares of common stock will be reclassified as Class A Common Stock. Each share of Class B Common Stock will have no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of shares of Class A Common Stock and shares of Class B Common Stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our second amended and restated certificate of incorporation (the “Proposed Second A&R Charter”), a copy of the form of which is attached to our proxy statement dated October 13, 2023 as Annex I. We do not intend to list any shares of Class B Common Stock on any exchange.

Following the Closing, under the amended and restated limited liability company agreement of OpCo (the “OpCo A&R LLC Agreement”), each holder of OpCo Class B Units will, subject to certain timing procedures and other conditions set forth therein, have the right (the “OpCo Exchange Right”) to exchange all or a portion of its OpCo Class B OpCo Units for, at OpCo’s election, (i) shares of our Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each OpCo Class B Unit exchanged, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions, or (ii) an equivalent amount of cash. OpCo will determine whether to pay cash in lieu of the issuance of shares of Class A Common Stock based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A Common Stock (including trading prices for the Class A Common Stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of stock) to acquire the OpCo Class B Units and alternative uses for such cash. Additionally, the holders of OpCo Class B Units will be required to exchange all of their OpCo Class B Units (a “Mandatory Exchange”) upon the occurrence of the following: (i) upon our direction of with the consent of at least fifty percent (50%) of the holders of OpCo Class B Units; or (ii) upon the one-year anniversary of the Mandatory Conversion Trigger Date.

In connection with any exchange of OpCo Class B Units pursuant to the OpCo Exchange Right or acquisition of OpCo Class B Units pursuant to a Mandatory Exchange, a corresponding number of shares of Class B Common Stock held by the relevant OpCo unitholder will be cancelled. 

The OpCo Preferred Units will be automatically converted into OpCo Class B Units on the two-year anniversary of the issuance date of such OpCo Preferred Units (the “Mandatory Conversion Trigger Date”) at a rate determined by dividing (i) $20.00 per unit (the “Stated Conversion Value”), by (ii) the Market Price of the Class A Common Stock (the “Conversion Price”). The “Market Price” means the simple average of the daily VWAP of the Class A Common Stock during the five (5) trading days prior to the date of conversion. On the Mandatory Conversion Trigger Date, we will issue a number of shares of Class B Common Stock to Seller equivalent to the number of OpCo Class B Units issued to Seller. If not exchanged sooner, such newly issued OpCo Class B Units shall automatically exchange into Class A Common Stock on the one-year anniversary of the Mandatory Conversion Trigger Date at a ratio of one OpCo Class B Unit for one share of Class Common Stock. An equivalent number of shares of Class B Common Stock must be surrendered with the OpCo Class B Units to us in exchange for the Class A Common Stock. As noted above, the OpCo Class B Units must be exchanged upon the one-year anniversary of the Mandatory Conversion Trigger Date.

Debt Commitment Letter

On August 28, 2023, we entered into a commitment letter (the “Debt Commitment Letter”) with First International Bank & Trust (“FIBT” or “Lender”), pursuant to which FIBT has agreed to provide us with a senior secured term loan in the amount of $28,000,000 (the “Credit Facility”) to (a) fund a portion of the purchase price, (b) partially fund a debt service reserve account funded with $3,000,000 at the Closing Date and an additional $2,000,000 to be deposited within 60 days following the Closing Date (the “Debt Service Reserve Account”), (c) cash secure outstanding letters of credit issued by Pogo’s existing lender, (d) pay fees and expenses in connection with the Purchase and the closing of the Credit Facility and (e) other general corporate purposes. The Credit Facility will be provided on the Closing Date subject to a number of specified conditions set forth in the Debt Commitment Letter. The obligations of FIBT to provide the Credit Facility will terminate on November 15, 2023 if the Closing Date has not occurred by such date. The definitive documentation for the Credit Facility has not been finalized and, accordingly, the actual terms of the Credit Facility may differ from those described in this prospectus.

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Option Agreement

In connection with the MIPA, OpCo and Seller agreed to cause the execution of an Option Agreement (the “Option Agreement”) by and between OpCo (or a newly created special purpose entity) and Pogo Royalty, LLC, a Texas limited liability company (“Pogo Royalty”), an affiliate of Seller. Pogo Royalty owns certain overriding royalty interests in certain oil and gas assets owned by Pogo Resources, LLC (the “ORR Interest”). Pursuant to the Option Agreement, Pogo Royalty will grant an irrevocable and exclusive option to us to purchase the ORR Interest for the Option Price (defined below) at any time prior to the date that is twelve (12) months following the effective date of the Option Agreement. The option will not be exercisable while the Seller Promissory Note is outstanding.

The purchase price for the ORR Interest upon exercise of the option shall be (i) (1) $30,000,000 the (“Base Option Price”), plus (2) an additional amount equal to interest on the Base Option Price of twelve percent (12%), compounded monthly, from the effective date of the Option Agreement through the date of acquisition of the ORR Interest, minus (ii) any amounts received by Pogo Royalty in respect of the ORR Interest from the month of production in which the effective date of the Option Agreement occurs through the date of the exercise of the option (such aggregate purchase price, the “Option Price”).

The Option Agreement and the option will immediately terminate upon the earlier of (a) Pogo Royalty’s transfer or assignment of all of the ORR Interest in accordance with the Option Agreement and (b) the date that is twelve (12) months following the effective date of the Option Agreement.

Director Nomination and Board Observer Agreement

In connection with the MIPA, at the Closing, we will enter into director nomination and board observer agreement (the “Board Designation Agreement”) with CIC. Pursuant to the Board Designation Agreement, CIC will have the right, at any time CIC beneficially owns capital stock of the Company, to appoint two board observers to attend all meetings of the board of directors of the Company. In addition, after the time of the conversion of the OpCo Preferred Units owned by Seller, CIC will have the right to nominate a certain number of members of the board of directors depending on its ownership percentage of Class A Common Stock as further provided in the Board Designation Agreement.

Backstop Agreement

We have agreed to, at Closing, enter into and cause certain of its founders (the “Founders”) to enter into the Backstop Agreement with Seller whereby the Seller will have the right (“Put Right”) to cause the Founders to purchase Seller’s OpCo Preferred Units at a purchase price per unit equal to $10.00 per unit plus the product of (i) the number of days elapsed since the effective date of the Backstop Agreement and (ii) $10.00 divided by 730. Seller’s right to exercise the Put Right will survive for six (6) months following the date the Trust Shares (as defined below) are not restricted from transfer under the Letter Agreement (as defined in the A&R MIPA).

As security that the Founders will be able to purchase the OpCo Preferred Units upon exercise of the Put Right, the Founders will agree to place 1,500,000 shares of Class A Common Stock into trust (the “Trust Shares”), which the Founders can sell or borrow against to meet their obligations upon exercise of the Put Right with the prior consent of Seller. The Company is not obligated to purchase the OpCo Preferred Units from Seller under the Backstop Agreement. Until the Backstop Agreement is terminated, Seller will not be permitted to engage in any transaction which is designed to sell short the Class A Common Stock of the Company or any other publicly traded securities of the Company.

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Founder Shares

On December 24, 2020, we issued an aggregate of 2,875,000 shares of common stock to the Sponsor for an aggregate purchase price of $25,000. Accordingly, as of December 31, 2020, the $25,000 payment due to the Company was recorded to the par value and additional paid-in-capital sections of the balance sheet. The agreement resulted in an aggregate of 2,875,000 shares of common stock held by the initial stockholders, of which an aggregate of up to 375,000 shares were subject to forfeiture to the extent that the underwriters’ over-allotment was not exercised in full or in part. On February 4, 2022, the Sponsor forfeited 373,750 shares as a result of a decrease in the size of our initial public offering, of which an aggregate of up to 326,250 of such shares was subject to forfeiture to the extent that the over-allotment option was not exercised by the underwriter in full or in part. No shares were forfeited since the underwriter did exercise the over-allotment in full. The Sponsor also acquired an additional 505,000 private placement shares, which were a part of the 505,000 private placement units acquired by the sponsor at the time of the initial public offering.

The founder shares are identical to the common stock previously included in the Units sold in the initial public offering except that the founder shares are and subject to certain transfer restrictions, as described in more detail below.

Contemporaneously with the Company’s initial public offering, the Sponsor transferred and sold 2,501,250 founder shares in private transactions to certain permitted transferees, including the shares being registered hereby for the resale by the Selling Securityholders.

All holders of our restricted common stock have agreed not to transfer, assign or sell any of their equity until the earlier of (A) 180 days after the completion of our initial business combination, or earlier if, subsequent to our initial business combination, the last sale price of our common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30-trading day period commencing at least 90 days after our initial business combination or (B) the date on which we complete a liquidation, merger, stock exchange or other similar transaction after the initial business combination that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property. We except that, in conjunction with the closing of our initial business combination, the restriction on transfer of only those shares being registered hereby for the resale by the Selling Securityholders will be waived and/or terminated.

Meeting to Approve the Business Combination

On October 13, 2023, we filed a definitive proxy statement with the SEC and promptly thereafter mailed the same to holders of record as of October 10, 2023 with respect to a special meeting of the stockholders of the Company to approve, among other things, the initial business combination, which is scheduled to take place on November 13, 2023 (the “BC Meeting”). A copy of that proxy statement is available at https://www.sec.gov/Archives/edgar/data/1842556/000101376223003769/defm14a1023_hnracqcorp.htm.

Meeting to Approve Charter Amendment to Extend Termination Date

On October 30, 2023, we filed a definitive proxy statement with the SEC and promptly thereafter mailed the same to holders of record as of October 27, 2023 with respect to a special meeting of the stockholders of the Company to approve, among other things, a charter amendment to extend the Termination Date (as defined in our Certificate of Amendment) beyond November 15, 2023 by up to two months, which such special meeting is scheduled to take place on November 14, 2023 (the “Extension Meeting”). A copy of that proxy statement is available at https://www.sec.gov/Archives/edgar/data/1842556/000121390023081411/def14a1023_hnracqusition.htm.  

Corporate Information

Our executive offices are located at 3730 Kirby Drive, Suite 1200, Houston, Texas 77098, and our telephone number is (713) 834-1145.

Pogo Information

Pogo is a private equity backed exploration and production company that began operations in February 2017. Pogo is based in Dallas, Texas, and a field office in Loco Hills, New Mexico. As of December 31, 2022, Pogo’s operating focus is the Northwest Shelf of the Permian Basin, with a specific emphasis on oil and gas producing properties located in the Grayburg-Jackson Field in Eddy County, New Mexico. Pogo is the Operator of Record of its oil and gas properties, operating its properties through its wholly owned subsidiary, LH Operating LLC. Pogo completed multiple acquisitions in 2018 and 2019. These acquisitions included multiple producing properties in Lea and Eddy counties, New Mexico. In 2020, after identifying its core development property, Pogo successfully completed a series of divestures of its non-core properties. Then, with one key asset, its Grayburg-Jackson Field in Eddy County, New Mexico, Pogo focused all of its efforts on developing this asset. This has been Pogo’s focus for 2021 and 2022. Pogo’s private equity sponsor is CIC Partners. Pogo’s equity backer, CIC Partners, has made an equity commitment of $15 million. Pogo’s bank, Pegasus Bank, provides an RBL credit facility for Pogo’s operations. Pogo seeks to maintain a conservative balance sheet. Currently, Pogo has 16 employees (3 executive officers and 1 engineering staff in Dallas; 12 field staff in Loco Hills). From time to time, on an as needed basis, contract workers handle additional necessary responsibilities.

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Pogo owns, manages, and operates, through its wholly owned subsidiary, LH Operating, LLC, 100% working interest in a gross 13,700 acres located on the Northwest Shelf of the prolific oil and gas producing Permian Basin. Pogo benefits from cash flow growth through continued development of its working interest’s ownership, with relatively low capital cost and lease operating expenses. As of December 31, 2022, average net daily production associated with Pogo’s working interests was 1,296 barrel of oil equivalent (“BOE”) per day consisting of 84% oil and 16% natural gas. Pogo expects to continue to grow its cash flow by production enhancements in its operations on its gross 13,700-acre leasehold. Furthermore, Pogo intends to make additional acquisitions within the Permian Basin, as well as other oil and gas producing regions in the USA, that meet its investment criteria for minimum risk, geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

As of December 31, 2022, 100% of Pogo’s gross 13,700 leasehold acres were located in Eddy County, New Mexico, where there 100% of the leasehold working interests owned by Pogo consist of state and federal lands. Pogo believes the Permian Basin offers some of the most compelling rates of return for Pogo and significant potential for cash flow growth. As a result of compelling rates of return, development activity in the Permian Basin has outpaced all other onshore U.S. oil and gas basins since the end of 2016. This development activity has driven basin-level production to grow faster than production in the rest of the United States.

Pogo’s working interests entitle it to receive an average of 84% of the net revenue from crude oil and natural gas produced from the oil and gas reservoirs underlying its acreage. Pogo is not under any mandatory obligation to fund drilling and completion costs associated with oil and gas development because 100% of its lease holdings are held by production. As a working interest owner with significant net earnings, Pogo seeks to fully capture all remaining oil and gas reserves underlying its leasehold acres by systematically developing its low risk, predictable, proven reserves by means of adding perforations in previously drilled and completed wells, were applicable, and drilling new wells in a predetermined drilling pattern. Accordingly, Pogo’s development model generates strong margins greater than 70%, at low risk, predictable, production outcomes that requires low overhead and is highly scalable. For the year ended December 31, 2022, Pogo’s lifting cost was about $17.79 per barrel of oil equivalent at a realized price of $84.41 per BOE, excluding the impact of settled commodity derivatives. As a result, Pogo’s operating margin and cash flows are higher, as a percentage of revenue, than those of traditional E&P companies. Pogo is led by a management team with extensive oil and gas engineering, geologic and land expertise, purchases and acquisitions and capital markets experience, long-standing industry relationships and a history of successfully acquiring and managing a portfolio of working and leasehold interests, producing crude oil and natural gas assets. Pogo intends to capitalize on its management team’s expertise and relationships to 1) increase cash flow in the field, 2) continue to make value-enhancing acquisitions in the Permian Basin, and 3) evaluate significant targets in other well-known producing basins in order to further increase its cash flows per share.

Pogo Market Conditions

The price that Pogo receives for the oil and natural gas we produce is largely a function of market supply and demand. Because Pogo’s oil and gas revenues are heavily weighted toward oil, Pogo is more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices.

Historically, commodity prices have been volatile, and Pogo expects the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Pogo’s Key Producing Region

As of December 31, 2022, all of Pogo’s properties were located exclusively within the Northwest Shelf of the Permian Basin. As of December 2022, the Permian Basin had the highest level of drilling activity in the United States with 344 drilling rigs operating, according to Baker Hughes. By comparison, The Eagle Ford Shale region located in Southwest-central Texas had only 72 rigs operating. The Permian Basin includes three major geologic provinces: the Delaware Basin to the west, the Midland Basin to the east and the Central Basin Platform in between. The Northwest Shelf is the western limits of the Delaware Basin, a sub-basin within the Permian Basin complex. The Delaware Basin is identified by an abundant amount of oil-in-place, stacked pay potential across an approximately 3,900-foot hydrocarbon column, attractive well economics, favorable operating environment, well developed network of oilfield service providers, and significant midstream infrastructure in place or actively under construction. One hundred percent (100%) of Pogo’s working interests are located as of December 31, 2022, on the New Mexico side of the Delaware Basin. According to the USGS, the Delaware Basin contains the largest recoverable reserves among all unconventional basins in the United States.

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Pogo believes the stacked-play potential of the Delaware Basin combined with favorable drilling economics support continued production growth as Pogo develops its leasehold position and improve well-spacing and completion techniques. Relative to other basins in the continental United States, Pogo believes the Delaware Basin is in a mid-stage of well development and that per-well returns will improve as Pogo continues to employ enhanced oil recovery technologies on its leasehold acreage. Pogo believes these enhanced oil recoveries will continue to support development activity where it holds significant working interest, with predictable returns leading to increasing cash flows with low maintenance costs.

Pogo’s Working Interests in Grayburg-Jackson Field

As of December 31, 2022, Pogo owns 100% working interest in 13,700 gross acres located in Eddy County, New Mexico, with a 84% weighted average net revenue. It should be noted that Pogo’s net revenue is substantially higher when compared to other E & P operators in the Permian Basin where their net revenue interest is usually 75%. The 13,700 gross acres are strategically located in the prolific oil field, Grayburg-Jackson field. Working interests granted to the Lessee (Pogo) under an Oil and Gas Lease are real property interests that grant ownership of the crude oil and natural gas underlying a specific tract of land and the rights to explore for, drill for and produce crude oil and natural gas on that land or to lease those exploration and development rights to a third party. Those rights to explore for, drill for and produce crude oil and natural gas on that land have a set period of time for the working interest owner to exercise those rights. Typically, an Oil and Gas Lease can be automatically extended beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease extension options. Only when production and drilling cease, the lease terminates.

As of December 31, 2022, 100% of Pogo’s working interests are held by production (“HBP”) meaning that Pogo is not under time sensitive obligation to drill or work-over any wells on its 13,700 acres. As of December 31, 2022, 100% of the wells and leases are operated by Pogo. Pogo is the official Operator of record with the state and federal regulatory agencies. As of December 31, 2022, Pogo generates a substantial majority of its revenues and cash flows from its working interests when crude oil and natural gas are produced and sold from its acreage.

Currently, Pogo’s working interests reside entirely in the Northwest Shelf of the Permian Basin, which Pogo believes is one of the premier crude oil and natural gas producing regions in the United States. As of December 31, 2022, Pogo’s working interests covered 13,700 gross acres, with the royalty owners retaining a weighted average 16% royalty. The following table summarizes Pogo’s working interest’s position in the lands comprising its leasehold as of December 31, 2022.

As of December 31, 2022, Pogo has working interests in 342 shallow (above 4,000 ft), vertical wells producing oil and gas in paying quantities. Ninety-five of the 342 producing wells were completed between 2019 and June 2022 by Pogo. In 2019, Pogo initiated a 4-well pilot water injection project into the Seven Rivers (“7R”) oil reservoir underlying its 13,700-acre leasehold. After an evaluation period extending into early 2020, Pogo determined the pilot project was successful by producing oil in paying quantities by simply adding perforations in the 7R reservoir in previously drilled and completed wells. Following the successful completion of the 4-well pilot project, Pogo commenced a work-over program by adding perforations in the 7R reservoir in 91 previously drilled wells between 2019 and June 2022. Prior to initiating the 4-well pilot project the legacy wells were averaging 275 BOE/d. By June 2022, the total production increased to 1,292 BOE/d. Pogo’s management team has determined, and verified by William M. Cobb & Associates (Cobb & Associates”), that 115 proved well patterns, developed but non-producing, are scheduled to be brought into production between 2023 and 2025.

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As of December 31, 2022, the estimated proved crude oil and natural gas reserves attributable to Pogo’s interests in its underlying acreage were 18,339 MBOE (96% oil and 4% natural gas), based on a reserve report prepared by Cobb & Associates, worldwide petroleum consultants. Of these reserves, approximately 35% were classified as proved developed producing (“PDP”) reserves, 39% were classified as proved developed non-producing (“PDNP”) reserves and 26% were classified as proved undeveloped (“PUD”) reserves. PUD reserves included in these estimates relate solely to wells that are not yet drilled nor were not yet producing in paying quantities as of December 31, 2022. Estimated proved reserves included in this section is presented on an actual basis, without giving pro forma effect to transactions completed after such dates.

Pogo believes its production and discretionary cash flows will grow significantly as Pogo completes its substantial PDNP inventory of 7R well patterns located on its gross 13,700 acreage. As of December 31, 2022, Pogo had production from 342 vertical wells, and it has identified 115 additional PDNP well patterns based on its assessment of current geological, engineering and land data. As of December 31, 2022, Pogo has identified 43 PUD well patterns based on its assessment of current geological, engineering and land data

Pogo’s working interest development strategy anticipates shifting any drilling activity associated with its PUD reserves following Pogo’s completion of its PDNP reserves. The work-over costs attributable to adding perforations in wells previously drilled and completed is significantly less than drilling new wells. As of December 31, 2022, Pogo’s leasehold position has 25.7 wells per square mile. Pogo expects to see increases in its production, revenue and discretionary cash flows from the development of 115 well patterns in the 7R reservoir. Pogo believes its current leasehold working interests provide the potential for significant long-term organic revenue growth as Pogo develops its PDNP reserves to increase crude oil and natural gas production.

Pogo Business Strategies

Pogo’s primary business objective is to generate discretionary cash flow by maintaining its strong cash flow from the PDP reserves and increasing cash flow by developing predictable, low cost PDNP reserves in its Permian Basin asset. Pogo intends to accomplish this objective by executing the following strategies:

Generate strong cash flow supported by means of disciplined development of its PDNP Reserves. As the sole working interest owner, Pogo benefits from the continued organic development of its acreage in the Permian Basin. As of December 31, 2022, Pogo, in conjunction with Cobb & Associates, a third-party engineering consulting firm, has confirmed that Pogo has 115, low cost, well patterns to be developed during 2023, 2024, and 2025. The total costs to complete these 115 well patterns have been predetermined by historical analysis. The estimated cost to complete each PDNP pattern is $377,652 and the estimated cost to complete each PUD pattern is $1,187,698. A single well pattern consists of one each producing well with its corresponding or dedicated water injection wells, with each injection well situated on four sides of the producing well. Water injection wells are necessary to maintain reservoir pressure in its original state and to move the oil in place toward the producing well. Pressure maintenance helps ensure maximum oil and gas recovery. Without pressure maintenance, oil recoveries from a producing oil reservoir generally do not exceed 10% of the original oil in place (“OOIP”). With pressure maintenance by re-injecting produced water into the oil reservoir, then Pogo expects to see ultimate oil recoveries 25% or greater of the OOIP. Offsetting oil wells on its leasehold also take advantage of the water injected into the oil reservoir, and is able to convert a high percentage of its revenue to discretionary cash flow, which it defines as its Adjusted EBITDA less cash interest expense and cash taxes. Because Pogo owns 100% working interests it incurs 100% of the monthly leasehold operating costs for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on its acreage. Because these wells are shallow oil producers, with vertical depths between 1500 ft and 4000 ft, the monthly operating expenses are relatively low.

As of December 31, 2022, on Pogo’s monthly leasehold operating expenses attributable to each PDNP well were $4,381 per month. Pogo also pays 100% of the capital expenditure to develop each well pattern. Pogo’s monthly cash operating costs for the production of crude oil and natural gas consist of certain severance taxes gathering, processing and transportation costs, labor, and general and administrative expenses. As of December 31, 2022, Pogo’s production and ad valorem taxes were approximately $7.05 per BOE at a realized price of $84.41 per BOE, excluding the impact of settled commodity derivatives. Pogo believes that its working interest’s ownership in Grayburg-Jackson Field are positioned for cash flow growth as Pogo continues to focus on developing its PDNP reserves identified by its management in conjunction with Cobb & Associates. Pogo also expects to continue to grow its cash flow by making acquisitions that meet its investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

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Focus primarily on the Permian Basin. All of Pogo’s working interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the United States. Pogo believes the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic and reservoir properties, opportunities for development with significant inventory of drilling locations and zones to be delineated our top-tier management team.

Pogo Competitive Strengths

Pogo believes that the following competitive strengths will allow it to successfully execute its business strategies and achieve its primary business objective:

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Pogo Internal Controls

Pogo’s internal staff of petroleum engineers and geoscience professionals work closely with its independent reserve engineer to ensure the integrity, accuracy and timeliness of data furnished to such independent reserve engineer in their preparation of reserve estimates. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. See “Other Risk Factors of Pogo” appearing elsewhere in this prospectus. Pogo’s engineering group is responsible for the internal review of reserve estimates Pogo’s Chief Operating Officer is primarily responsible for overseeing the preparation of its reserve estimates and has more than 16 years of experience as an engineer. Pogo’s Chief Executive Officer is directly responsible for overseeing the engineering group.

No portion of Pogo’s engineering group’s compensation is directly dependent on the quantity of reserves booked. The engineering group reviews the estimates with the third-party petroleum consultant, Cobb & Associates, an independent petroleum engineering firm.

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Pogo Regulation

The following disclosure describes regulations directly associated with E&P companies who are classified with state and federal regulatory agencies as Operator of record of crude oil and natural gas properties, including Pogo.

Crude oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.

Environmental Matters

Crude oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which Pogo owns working interest, which could materially adversely affect its business and its prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the Operator of record regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect Pogo’s business and prospects.

Non-Hazardous and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update its RCRA Subtitle D criteria regulations governing the disposal of certain crude oil and natural gas drilling wastes. In December 2016, EPA and the environmental groups entered into a consent decree to address EPA’s alleged failure. In response to the consent decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. However, any changes in the laws and regulations could have a material adverse effect on the Operator of record (Pogo) of its properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying Pogo’s working interests and adversely affect Pogo’s business and prospects.

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Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose Pogo’s working interests underlying its leasehold acreage to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require Pogo to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The Clean Water Act (“CWA”), the SDWA, the Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years. The EPA and U.S. Army Corps of Engineers published a revised definition on January 18, 2023, which has been challenged in court. To the extent any future rule expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on Pogo.as the Operator of record. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Production EPA has also adopted regulations requiring certain crude oil and natural gas facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subject’s owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.

Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the Operator of record (Pogo) underlying its leasehold working interest.

Air Emissions

The CAA, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying Pogo’s working interests. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.

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Climate Change

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised regulations initially promulgated in June 2016 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. The EPA issued supplemental rules regarding methane emissions on December 6, 2022. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, which may apply to our operations in the future and may require us to expend material sums. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The full impact of these actions cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an Executive Order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for restrictions on leasing on federal land, including the Department of the Interior’s publication of a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. Substantially all of Pogo’s interests are located on state and federal, and it cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

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There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2021, the Federal Reserve announced that it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of Pogo’s working interests. Additionally, political, litigation and financial risks may result in Pogo restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of Pogo’s working interests. One or more of these developments could have a material adverse effect on Pogo’s business, financial condition and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations and Pogo’s supply chains. Such physical risks may result in damage to Pogo’s facilities or otherwise adversely impact our operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, Pogo is unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting its business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs.

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However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that establish new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years. For more information, see “Risk Factors titled “Pogo’s Operations,” as with many E&P operators, are subject to a series of risks arising from climate change.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Railroad Commission of Texas has previously issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Railroad Commission of Texas has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In late 2021, the Railroad Commission of Texas issued a notice to operators of disposal wells in the Midland area, to reduce saltwater disposal well actions and provide certain data to the commission. Separately, in November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. As a result of these developments, Pogo as the Operator of record may be required to curtail operations or adjust development plans, which may adversely impact Pogo’s business.

The USGS has identified six states with the most significant hazards from induced seismicity, including New Mexico, Oklahoma and Texas. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on Pogo’s properties and on their waste disposal activities.

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If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause Pogo to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on Pogo’s financial condition and results of operations. At this time, it is not possible to estimate the impact on Pogo’s business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Endangered Species Act

The ESA restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA. For example, in October 2019 environmental groups filed a lawsuit against the FWS seeking to compel the agency to list the species under the ESA, and in July 2020, FWS agreed to initiate a 12-month review to determine whether listing the species was warranted, which determination remains outstanding. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA, which was finalized on November 25, 2022. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where Pogo’s properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on Pogo’s properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Other Regulation of the Crude Oil and Natural Gas Industry

The crude oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and conditions and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.

Pogo cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on its operations. Sales of crude oil and condensate are not currently regulated and are made at market prices.

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Drilling and Production

The operations on Pogo’s properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which Pogo operates also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce Pogo’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the Pogo’s properties can produce from Pogo’s wells or limit the number of wells or the locations at which can be drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but Pogo cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from Pogo’s wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where Pogo operates. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which Pogo’s properties may use interstate natural gas pipeline capacity, as well as the revenues received for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

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Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that Pogo’s properties produce.

Historically, the natural gas industry was more heavily regulated; therefore, Pogo cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will continue indefinitely into the future nor can Pogo determine what effect, if any, future regulatory changes might have on its natural gas related activities.

Crude Oil Sales and Transportation

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, Pogo believes that the regulation of crude oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of its competitors.

Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, Pogo believes that access to crude oil pipeline transportation services of Pogo’s properties will not materially differ from Pogo’s competitors’ access to crude oil pipeline transportation services.

State Regulation

New Mexico regulates the drilling for, and the production, gathering and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. New Mexico currently imposes a 3.75% severance tax on the market value of crude oil and natural gas production as well as other production taxes for conservation, schools, ad valorem, and equipment. Combined, these taxes amount to 8-9% tax on market value of crude and natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of crude oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but Pogo cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on Pogo’s properties and the number of wells or locations Pogo’s properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. Pogo does not believe that compliance with these laws will have a material adverse effect on its business.

Pogo Title to Properties

Prior to completing an acquisition of a target or working interests, Pogo performs a title review on each tract to be acquired. Pogo’s title review is meant to confirm the working interests owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens. As a result, title examinations have been obtained on substantially all of Pogo’s properties.

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In addition to Pogo’s initial title work, Pogo often will conduct a thorough title examination prior to leasing any new acres, and/or drilling a well. Should any further title work uncover any further title defects, Pogo will perform curative work with respect to such defects. Pogo generally will not commence drilling operations on a property until any material title defects on such property have been cured.

Pogo believes that the title to its assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary royalty interest generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests and other burdens, easements, restrictions or minor encumbrances customary in the crude oil and natural gas industry, Pogo believes that none of these encumbrances will materially detract from the value of these properties or from its interest in these properties.

Pogo Competition

The crude oil and natural gas business is highly competitive; Pogo primarily competes with companies for the acquisition of targets with high percentage of working interests underlying crude oil and natural gas leases. Many of Pogo’s competitors not only own and acquire working interests but also explore for and produce crude oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By engaging in such other activities, Pogo’s competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, certain of Pogo’s competitors may possess financial or other resources substantially larger than Pogo possesses. Pogo’s ability to acquire additional working interests and properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, crude oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of crude oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for crude oil and natural gas.

Pogo Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting Pogo’s overall business plans. Additionally, Pogo’s properties are located in areas adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, Pogo may be unable to move their equipment between locations, thereby reducing its ability to operate Pogo’s wells, reducing the amount of crude oil and natural gas produced from the wells on Pogo’s properties during such times. Additionally, extended drought conditions in the areas in which Pogo’s properties are located could impact its ability to source sufficient water or increase the cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for Pogo’s natural gas production during its first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other crude oil and natural gas operations in Pogo’s operating areas. Due to these seasonal fluctuations, Pogo’s results of operations for individual quarterly periods may not be indicative of the results that it may realize on an annual basis.

Pogo Employees

Pogo has salaried and regular pay employees in the field. As of December 31, 2022, Pogo employed 13 full-time salaried and regular pay field individuals under no ongoing employment contracts who provided direct support to Pogo’s operations. None of these employees are covered by collective bargaining agreements. Immediately after the Closing, Pogo expects to employ 4-6 individuals, top-level management, none of which are expected to be covered by collective bargaining agreements.

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SUMMARY RISK FACTORS

You should carefully read this prospectus, including the section entitled “Risk Factors.” Certain of the key risks are summarized below.

Risks Related to Pogo

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Risks Related to Pogo’s Industry

Risks Related to Environmental and Regulatory Matters

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Risks Related to Pogo’s Financial and Debt Arrangements

General Risks Related to Pogo

Risk Factors Related to the Purchase

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Risks Related to Our Business

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Risks Related to our Common Stock and this Offering

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ABOUT THIS OFFERING

This prospectus relates to the resale by the non-affiliate Selling Securityholders identified in this prospectus of up to 1,320,625 shares of common stock. All of the shares, when sold, will be sold by the Selling Securityholders. The shares offered by this prospectus may be sold in the open market at prevailing prices, through privately negotiated transactions or a combination of these methods. We will not receive any proceeds from the sale of the shares of common stock by the Selling Securityholders.

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SUMMARY HISTORICAL FINANCIAL INFORMATION OF HNRA

The following table presents selected historical financial data for the periods indicated. The selected historical financial data as of and for the years ended December 31, 2022 and 2021 is derived from HNRA’s audited financial statements and related notes thereto. The financial statements and related notes thereto are included elsewhere in this prospectus for the years ended December 31, 2022 and 2021. The selected historical financial data for the six-months ended June 30, 2023 and 2022 have been derived from HNRA’s unaudited financial statements included elsewhere in this prospectus.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations of HNRA.” The following table should also be read in conjunction with the historical financial statements of HNRA included in its Form 10-K for the year ended December 31, 2022 and 2021 filed with the SEC on March 31, 2023. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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SUMMARY HISTORICAL CONSOLIDATED FINANCIAL INFORMATION OF POGO

The following table presents selected historical consolidated financial data for the periods indicated. The summary historical consolidated financial data as of and for the years ended December 31, 2022, 2021 and 2020 is derived from Pogo’s audited consolidated financial statements and related notes thereto. The audited consolidated financial statements and related notes thereto for the year ended December 31, 2022 and 2021 are included elsewhere in this prospectus. The selected historical consolidated financial data for the six months ended June 30, 2023 and 2022 have been derived from Pogo’s unaudited consolidated financial statements included elsewhere in this prospectus.

Pogo’s historical results are not necessarily indicative of the results that may be expected for any other period in the future. For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Pogo.” The following table should also be read in conjunction with the historical financial statements of Pogo included elsewhere in this prospectus. Among other things, the historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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SUMMARY UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

The following summary unaudited pro forma combined financial information, or the Summary Pro Forma Information, gives effect to the transactions contemplated by the Purchase. The Purchase will be accounted for using the acquisition method of accounting, with HNRA as the acquiring entity. Under the acquisition method of accounting, HNRA’s assets and liabilities will retain their carrying values and the assets and liabilities associated with Pogo will be recorded at their fair values measured as of the Closing date. The excess of the purchase price over the estimated fair values of the net assets acquired, if applicable, will be recorded as goodwill. The acquisition method of accounting is based on ASC 805 and uses the fair value concepts defined in ASC Topic 820, Fair Value Measurements. The summary unaudited pro forma combined balance sheet data as of June 30, 2023 gives effect to the Purchase and related transactions as if they had occurred on June 30, 2023. The summary unaudited pro forma combined statements of operations data for the six months ended June 30, 2023 and the year ended December 31, 2022 present the pro forma effect of the Purchase and Acquisition as if they had been completed on January 1, 2022.

The SEC adopted Release No. 33-10786 “Amendments to Financial Disclosures about Acquired and Disposed Businesses” in May 2020, or the “Release”, with an effective date of January 1, 2021. The amendments of the Release replace existing pro forma adjustment criteria with simplified requirements to depict the accounting for the transaction under GAAP, which we refer to as Transaction Accounting Adjustments, and allow HNRA the option to present reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur, which we refer to as Management’s Adjustments. HNRA has elected to not present Management’s Adjustments and will only present Transaction Accounting Adjustments.

The summary unaudited pro forma financial information has been derived from, and should be read in conjunction with, the more detailed unaudited pro forma combined financial information of the post-combination company appearing elsewhere in this prospectus and the accompanying notes to the unaudited pro forma condensed combined financial information. The unaudited pro forma condensed combined financial information is based upon, and should be read in conjunction with, the historical financial statements and related notes of HNRA and Pogo for the applicable periods included in this prospectus. The Summary Pro Forma Information has been presented for informational purposes only and is not necessarily indicative of what the post-combination company’s financial position or results of operations actually would have been had the Purchase been completed as of the dates indicated. In addition, the Summary Pro Forma Information does not purport to project the future financial position or operating results of the post-combination company.

The unaudited pro forma condensed combined financial statements are presented in three scenarios: (1) assuming no redemptions, or the No Redemptions scenario, (2) assuming 50% redemptions, or the Interim Redemptions scenario and (3) assuming maximum redemptions, or the Maximum Redemptions scenario. All three scenarios reflect the deposit into the Trust Account of $120,000 as payment of the July 11, 2023 extension payment, the deposit of $120,000 as payment of the August 7, 2023 extension payment, the deposit of $120,000 as payment of the September 11, 2023 extension payment, and the deposit of $120,000 as payment of the October 13, 2023 extension payment.

No Redemptions Scenario. This presentation assumes that none of the HNRA stockholders exercises redemption rights with respect to its redeemable common stock for a pro rata portion of the funds in the Trust Account.

Interim Redemptions Scenario. This presentation assumes that HNRA stockholders holding 4,509,403 redeemable common stock exercise their redemption rights with respect to 2,254,702 (50% of the issued and outstanding shares) redeemable common stock and that such Public Shares are redeemed for their pro-rata share (approximately $10.63 per share) of the funds in the Trust Account for aggregate redemption proceeds of approximately $24.0 million.

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Maximum Redemptions Scenario. This presentation assumes that HNRA stockholders holding 4,509,403 redeemable common stock exercise their redemption rights and that such Public Shares are redeemed for their pro rata share (approximately $10.63 per share) of the funds in the Trust Account for aggregate redemption proceeds of approximately $47.9 million. Our amended and restated certificate of incorporation will not provide a specified maximum redemption threshold, except that in no event will we redeem our public shares in an amount that would cause our net tangible assets to be less than $5,000,001 upon the consummation of our initial business combination (such that we become subject to the SEC’s “penny stock” rules) or any greater net tangible asset or cash requirement which may be contained in the agreement relating to our initial business combination. As a result, we may be able to complete our business combination even though a substantial majority of our public stockholders do not agree with the transaction and have redeemed their shares or, if we seek stockholder approval of our initial business combination and do not conduct redemptions in connection with our business combination pursuant to the tender offer rules, have entered into privately negotiated agreements to sell their shares to our sponsor, officers, directors, advisors or their affiliates. In the event the aggregate cash consideration we would be required to pay for all shares of common stock that are validly submitted for redemption plus any amount required to satisfy cash conditions pursuant to the terms of the proposed business combination exceed the aggregate amount of cash available to us, we will not complete the business combination or redeem any shares, all shares of common stock submitted for redemption will be returned to the holders thereof, and we instead may search for an alternate business combination.

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